Classifications

• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/60—Compositions for stimulating production by acting on the underground formation
  • C09K8/62—Compositions for forming crevices or fractures
  • C09K8/64—Oil-based compositions
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/02—Well-drilling compositions
  • C09K8/32—Non-aqueous well-drilling compositions, e.g. oil-based
  • C09K8/36—Water-in-oil emulsions
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/60—Compositions for stimulating production by acting on the underground formation
  • C09K8/62—Compositions for forming crevices or fractures
  • C09K8/66—Compositions based on water or polar solvents
  • C09K8/68—Compositions based on water or polar solvents containing organic compounds
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/60—Compositions for stimulating production by acting on the underground formation
  • C09K8/62—Compositions for forming crevices or fractures
  • C09K8/72—Eroding chemicals, e.g. acids
  • C09K8/725—Compositions containing polymers
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/60—Compositions for stimulating production by acting on the underground formation
  • C09K8/82—Oil-based compositions
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/25—Methods for stimulating production
  • E21B43/26—Methods for stimulating production by forming crevices or fractures
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
  • C09K2208/14—Double emulsions, i.e. oil-in-water-in-oil emulsions or water-in-oil-in-water emulsions
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
  • C09K2208/28—Friction or drag reducing additives

Definitions

• Also provided is a method of treating a portion of a subterranean formation that includes the steps of: providing a water-in-oil emulsion; inverting the water-in-oil emulsion by adding it to water at from about 0.1 to about 3 gallons of water-in-oil emulsion per thousand gallons of water to form a friction reducing treatment solution containing from about 0.0025 to less than about 0.1 % water-soluble polymer based on the weight of the treatment solution; and introducing the treatment solution into the portion of the subterranean formation.
• the oil phase (O) and the aqueous phase (A) can be present at an O/A ratio, based on the volume of each phase of from at least about 1 :8, in some cases at least about 1 :6 and in other cases at least about 1 :4 and can be up to about 10: 1, in some cases up to about 8: 1 and in other cases up to about 6: 1.
• O/A ratio is too oil heavy, the polymer may be too concentrated in the aqueous phase.
• the O/A ratio is too water heavy, the emulsion may become unstable and prone to separate.
• the O/A ratio can be any ratio or range between any of the ratios recited above.
• fatty acid esters of sorbitan for instance sorbitan monoleate, sorbitan dioleate, sorbitan trioleate, sorbitan monostearate and sorbitan tristearate;
• fatty acid esters of mannitol for instance mannitol monolaurate or mannitol monopalmitate;
• fatty acid esters of glucose for instance glucose monooleate and glucose monostearate
• the water soluble polymer is present at a level of at least about 5, in some instances 10, in some cases at least about 15, and in other cases at least about 20 weight percent based on the weight of the water-in-oil emulsion and can be present at up to about 33, in some cases up to about 35, in other cases up to about 37 and in some instances up to about 40 weight percent based on the weight of the water-in-oil emulsion.
• the amount of water soluble polymer is too low, the use of the water-in- oil emulsion in the present method of treating a portion of a subterranean formation may be uneconomical.
• the water soluble polymer in the water-in-oil emulsion is prepared by polymerizing a monomer solution that includes at least one (meth)acrylamide monomer and at least one (meth)acrylic acid monomer containing monomers included at a level that provides the desired amount of water soluble polymer.
• the monomer mixture typically includes (meth)acrylic acid and/or its corresponding salts, non-limiting examples being sodium, potassium and ammonium.
• the amount of (meth)acrylic acid can be at least about 10, in some cases at least about 12, and in other cases at least about 14 weight percent based on the weight of the monomer mixture. When the amount of (meth)acrylic acid is too low, the water soluble polymer may not carry enough ionic charge to optimally function as a friction reducing polymer. Also, the amount of (meth)acrylic acid in the monomer mixture can be up to about 40, in some case up to about 18, and in other cases up to about 16 weight percent based on the weight of the monomer mixture.
• the water soluble polymer may have undesirable flocculation properties when used in the present method.
• the amount of (meth)acrylic acid in the monomer mixture can be any value or range between any of the values recited above.
• the water soluble polymer can include other monomers to provide desirable properties to the polymer.
• suitable other monomers that can be included in the monomer mixture, and ultimately the resulting water soluble polymer include 2-acrylamido-2-methylpropane sulfonic acid (AMPS) and acryloyloxyethyl trimethyl ammonium chloride (AETAC).
• AMPS 2-acrylamido-2-methylpropane sulfonic acid
• AETAC acryloyloxyethyl trimethyl ammonium chloride
• polymerized residues of AMPS can be present in the monomer mixture of the present invention in an amount in the range of from about 0.1% to about 30%, in some cases about 0.5% to about 20%, and in other cases from about 1% to about 10% by weight of the monomer mixture.
• the monomer mixture includes acrylamide in an amount in the range of from about 70% to about 85% by weight, acrylic acid in an amount in the range of from about 10% to about 12.5% by weight, and 2-acrylamido-2-methylpropane sulfonic acid in an amount in the range of from about 2.5% to about 20% by weight of the monomer mixture.
• the water soluble polymers of the present disclosure can reduce energy losses during introduction of the aqueous treatment fluid into a well bore due to friction between the aqueous treatment fluid in turbulent flow and the formation and/or tubular good(s) (e.g., a pipe, coiled tubing, etc.) disposed in the well bore.
• the water-in-oil emulsion containing the water soluble polymer of the present method is prepared using water-in-oil emulsion polymerization techniques. Suitable methods to effect such polymerizations are known in the art, non-limiting examples of such being disclosed in U.S. Patent Nos.
• Any suitable initiator can be used.
• suitable initiators include diethyl 2,2'-azobisisobutyrate, dimethyl 2,2'-azobisisobutyrate, 2-methyl 2'-ethyl azobisisobutyrate, benzoyl peroxide, lauroyl peroxide, sodium persulfate, potassium persulfate, tert-butyl hydroperoxide, dimethane sulfonyl peroxide, ammonium persulfate, azobisisobutylronitrile, dimethyl 2,2'-azobis (isobutyrate) and combinations thereof.
• the polymerization technique may have an initiation temperature of about 25°C and proceed approximately adiabatically. In other embodiments of the disclosure, the polymerization can be carried out isothermally at a temperature of about from 37°C to about 50 °C.
• the oil-in-water emulsion can include a salt.
• the salt can be present to add stability to the emulsion and/or reduced viscosity of the emulsion.
• suitable salts include, but are not limited to, ammonium chloride, potassium chloride, sodium chloride, ammonium sulfate, and mixtures thereof.
• the salt can be present in emulsions in an amount in the range of from about 0.5% to about 2.5% by weight of the emulsion.
• the oil-in-water emulsions can include an inhibitor.
• the inhibitor can be included to prevent premature polymerization of the monomers prior to initiation of the emulsion polymerization reaction.
• the water soluble polymer may have been synthesized using an emulsion polymerization technique wherein the inhibitor acted to prevent premature polymerization.
• suitable inhibitors include, but are not limited to, quinones.
• An example of a suitable inhibitor comprises a 4-methoxyphenol (MEHQ).
• MEHQ 4-methoxyphenol
• the inhibitor should be present in an amount sufficient to provide the desired prevention of premature polymerization.
• the inhibitor may be present in an amount in the range of from about 0.001%) to about 0.1%> by weight of the emulsion.
• the water soluble polymers of the disclosed subject matter typically have a molecular weight sufficient to provide a desired level of friction reduction.
• friction reducing polymers have a higher molecular weight in order to provide a desirable level of friction reduction.
• the weight average molecular weight of the friction reducing copolymers may be in the range of from about 2,000,000 to about 20,000,000, in some cases up to about 30,000,000, as determined using intrinsic viscosities.
• friction reducing copolymers having molecular weights outside the listed range may still provide some degree of friction reduction in an aqueous treatment fluid.
• the water-in-oil emulsion is added to water by inverting the emulsion to form a friction reducing treatment solution.
• invert and/or “inverting” refer to exposing the water-in-oil emulsion to conditions that cause the aqueous phase to become the continuous phase. This inversion releases the water soluble polymer into the make-up water.
• an inverting surfactant can be included in the water-in-oil emulsion.
• the inverting surfactant can facilitate the inverting of the emulsion upon addition to make up water and/or the aqueous treatment fluids of the disclosed subject matter.
• the water-in-oil emulsion upon addition to the aqueous treatment fluid, the water-in-oil emulsion should invert, releasing the copolymer into the aqueous treatment fluid.
• Non-limiting examples of suitable inverting surfactants include, polyoxyethylene alkyl phenol; polyoxyethylene (10 mole) cetyl ether; polyoxyethylene alkyl-aryl ether; quaternary ammonium derivatives; potassium oleate; N-cetyl-N-ethyl morpholinium ethosulfate; sodium lauryl sulfate; condensation products of higher fatty alcohols with ethylene oxide, such as the reaction product of oleyl alcohol with 10 ethylene oxide units; condensation products of alkylphenols and ethylene oxide, such as the reaction products of isooctylphenol with 12 ethylene oxide units; condensation products of higher fatty acid amines with five, or more, ethylene oxide units; ethylene oxide condensation products of polyhydric alcohol partial higher fatty esters, and their inner anhydrides (e.g., mannitol anhydride, and sorbitol-anhydride).
• ethylene oxide condensation products of polyhydric alcohol partial higher fatty esters and their inner anhydr
• the inverting surfactants can include ethoxylated nonyl phenols, ethoxylated nonyl phenol formaldehyde resins, ethoxylated alcohols, nonionic surfactants with an HLB of from 12 to 14, and mixtures thereof.
• a specific non-limiting example of a suitable inverting surfactant includes an ethoxylated C 12 - C 16 alcohol.
• the inverting surfactant can be a C 12 - C 14 alcohol having 5 to 10 units of ethoxylation.
• the inverting surfactant can be present in an amount sufficient to provide the desired inversion of the emulsion upon contact with the water in the aqueous treatment fluid.
• a batch method can be used to make down the water-in-oil emulsion.
• the water soluble polymer containing water-in-oil emulsion and water are delivered to a common mixing tank. Once in the tank, the solution is beat or mixed for a specific length of time in order to impart energy thereto. After mixing, the resulting solution must age to allow enough time for the molecules to unwind. This period of time is significantly reduced in the present disclosure.
• continuous in-line mixers as well as in-line static mixers can be used to combine the water soluble polymer containing water-in-oil emulsion and water.
• suitable mixers utilized for mixing and feeding are disclosed in U.S. Patent Nos. 4,522,502; 4,642,222; 4,747,691; and 5,470,150, which are incorporated herein by reference.
• suitable static mixers can be found in U.S. Patent Nos. 4,051,065 and 3,067,987, which are incorporated herein by reference.
• any other additives are added to the solution to form a treatment solution, which is then introduced into the portion of the subterranean formation.
• the water soluble polymer can be included in any aqueous treatment fluid used in subterranean treatments to reduce friction.
• Such subterranean treatments include, but are not limited to, drilling operations, stimulation treatments (e.g., fracturing treatments, acidizing treatments, fracture acidizing treatments), and completion operations.
• stimulation treatments e.g., fracturing treatments, acidizing treatments, fracture acidizing treatments
• completion operations e.g., completion operations.
• the water used in the aqueous treatment fluids of the disclosed subject matter can be freshwater, saltwater (e.g., water containing one or more salts dissolved therein), brine (e.g., produced from subterranean formations), seawater, pit water, pond water -or- the like, or combinations thereof.
• the water used may be from any source, provided that it does not contain an excess of compounds that may adversely affect other components in the aqueous treatment fluid or the formation itself.
• the disclosed subject matter is effective in all aqueous treating fluid waters.
• the water soluble polymer can be present in aqueous treatment fluids in an amount in the range of from about 0.0025%) to about 0.025%), in some cases in the range of from about 0.0025%> to less than about 0.01%, in other cases in the range of from about 0.0025%) to about 0.009%), and in some situations in the range of from about 0.0025%> to about 0.008%, by weight of the aqueous treatment fluid.
• the amount of water soluble polymer in the aqueous treatment fluid can be at least about 5%, in some cases at least about 7.5%, in other cases at least about 10%, in some instances at least about 12.5%, in other instances at least about 15%, in some situations at least about 20%), and in other situations at least about 25% less than when water-in-oil emulsion containing a polymer of the same composition at a concentration of 30 weight percent or more are used in the in the aqueous treatment fluid.
• the water-in-oil emulsions according to the disclosure are used in the friction reducing treatment solution in an amount of at least about 0.1 gallons of water-in-oil emulsion per thousand gallons of aqueous treating fluid water (gpt), in some cases at least about 0.15 gpt, and in other cases at least about 0.2 gpt and can be up to about 3 gpt, in some cases up to about 2.5 gpt, in other cases up to about 2.0 gpt, in some instances up to about 1.5 gpt, and in other instances up to about 1.5 gpt.
• the amount of water-in-oil emulsion used in the friction reducing treatment solution can be any value or range between any of the values recited above.
• the aqueous treatment fluid contains 10,000 to 300,000 ppm of total dissolved solids.
• the total dissolved solids include at least 10 weight percent of a multivalent cation.
• the any multivalent cation can be included and can include one or more selected from iron (in its ferrous and ferric forms), calcium, magnesium, manganese, strontium, barium, and zinc.
• the aqueous treatment fluid can include total dissolved solids at a level of at least about 100 ppm, in some instances at least about 500 ppm, in other instances at least about 1,000 ppm, in some cases at least about 5,000 ppm and in other cases at least about 10,000 ppm and can be up to about 500,000 ppm, in certain cases up to about 400,000 ppm, in many cases up to about 300,000 ppm, in some cases up to about 250,000 ppm, in other cases up to about 200,000 ppm, in some instances up to about 100,000 ppm, in other instances up to about 50,000 ppm and in some situations up to about 25,000 ppm.
• the amount of total dissolved solids in the aqueous treatment solution can be any value or range between any of the values recited above.
• the lower polymer usage when the present invention is used results in significantly decreased formation damage, decreased flocculation in above ground fluid recycle operations, and is more environmentally friendly as lower levels of polymer are used. Additionally, the lower polymer dose can be delivered using existing equipment resulting in better performance with little or no capital cost requirement.
• Additional additives can be included in the aqueous treatment fluids of the present disclosure as deemed appropriate by one of ordinary skill in the art, with the benefit of this disclosure.
• additives include, but are not limited to, corrosion inhibitors, proppant particulates, acids, fluid loss control additives, and surfactants.
• an acid may be included in the aqueous treatment fluids, among other things, for a matrix or fracture acidizing treatment.
• proppant particulates may be included in the aqueous treatment fluids to prevent the fracture from closing when the hydraulic pressure is released.
• the aqueous treatment fluids of the present disclosure can be used in any subterranean treatment where the reduction of friction is desired.
• Such subterranean treatments include, but are not limited to, drilling operations, stimulation treatments (e.g., fracturing treatments, acidizing treatments, fracture acidizing treatments), and completion operations.
• stimulation treatments e.g., fracturing treatments, acidizing treatments, fracture acidizing treatments
• completion operations e.g., completion operations.
• the disclosed subject matter includes a method of treating a portion of a subterranean formation that includes providing the above-described aqueous treatment fluid and introducing the aqueous treatment fluid into the portion of the subterranean formation.
• the aqueous treatment fluid can be introduced into the portion of the subterranean formation at a rate and pressure sufficient to create or enhance one or more fractures in the portion of the subterranean formation.
• the portion of the subterranean formation that the aqueous treatment fluid is introduced will vary dependent upon the particular subterranean treatment.
• the portion of the subterranean formation may be a section of a well bore, for example, in a well bore cleanup operation.
• the portion may be the portion of the subterranean formation to be stimulated.
• the methods of the present disclosure can also include preparing the aqueous treatment fluid.
• Preparing the aqueous treatment fluid can include providing the water soluble polymer containing water-in-oil emulsion and combining the water soluble polymer with the water to from the aqueous treatment fluid.
• Table 1 presents the ingredients (expressed in weight percent of total composition) in the aqueous monomer phase, oil phase and surfactants for water-in-oil emulsion synthesis.
• Typical preparation included the mixing of water, acrylamide, acrylic acid, hydroquinone monomethyl ether (MEHQ), ethylene diamine tetra acetic acid (EDTA), water-soluble hydrophobic monomer(s) and 25% sodium hydroxide until all dissolved to form uniform aqueous phase.
• the oil phase consists of well-mixed hydrophobic liquid, water-insoluble hydrophobic monomer and indicated surfactants.
• the aqueous phase was then added to the oil phase with mixing to form dispersion of the aqueous phase dispersed in the continuous oil phase.
• the dispersion was purged with nitrogen while being heated to an initiation temperature of about 28 degrees C and then a water soluble free radical initiator was added to initiate the polymerization.
• a water soluble free radical initiator was added to initiate the polymerization.
• the oil phase was first added to a glass resin kettle and once the agitation was on, the aqueous phase was added to the kettle.
• the dispersion was purged with nitrogen for 30 minutes while being heated and stabilized at 28 degrees C, at which time 19 microliters of peroxide was added to the agitated dispersion and 0.05% sodium metabisulfate (SMBS) was fed into the resin kettle at a rate of 0.1 ml per minute.
• the polymerization temperature was maintained between 48 to 52 degrees C for about 90 minutes.
• Residual monomers were scavenged using concentrated SMBS with a feeding rate of 1 ml per minutes for 10 minutes. Appropriate amount of inverting surfactant was then slowly added to the water-in-oil emulsion to aid the make-down upon use.
• the emulsions shown in Table 1 include a water soluble polymer containing aciylamide/acrylic acid in a weight ratio of 70/30 along with 0.1 wt% to 1 wt% of the hydrophobic monomers.
• compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of or “consist of the various components, substances and steps. As used herein the term “consisting essentially of shall be construed to mean including the listed components, substances or steps and such additional components, substances or steps which do not materially affect the basic and novel properties of the composition or method.

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• 2016
  • 2016-02-23 EP EP16709200.6A patent/EP3262136B1/de active Active
  • 2016-02-23 HU HUE16709200A patent/HUE053787T2/hu unknown
  • 2016-02-23 CA CA2977371A patent/CA2977371C/en active Active
  • 2016-02-23 US US15/050,824 patent/US20160251567A1/en not_active Abandoned
  • 2016-02-23 AU AU2016222978A patent/AU2016222978A1/en not_active Abandoned
  • 2016-02-23 WO PCT/US2016/019062 patent/WO2016137945A2/en not_active Ceased
  • 2016-02-23 CN CN201680012274.XA patent/CN107278223A/zh active Pending
• 2020
  • 2020-08-31 US US17/007,284 patent/US11795376B2/en active Active
• 2023
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